The production of hydrocarbons from subterranean formations is often effected by the presence of clays and other fines, which can migrate and plug off or restrict the flow of the hydrocarbon product. The migration of fines in a subterranean formation is often the result of clay swelling, salt dissolution, and/or the disturbance of fines by the introduction of fluids that are foreign to the formation. Typically, a foreign fluid (e.g., fracturing fluid or stabilizing fluid) is introduced into the formation for the purpose of completing and/or treating the formation to stimulate production of hydrocarbons by, for example, fracturing, acidizing, or stabilizing the well.
The fracturing fluids used throughout the oil and gas industry are based on a low-cost anionic friction reducer in combination with a clay stabilizer (e.g., choline chloride and/or trimethylamine). These fracturing fluids work adequately in formations where there is a relative high level of permeability, expressed in millidarcy.
The anionic friction reducer facilitates the fracturing of the subterranean formation by allowing the system to achieve a desired pressure in the fracturing zone and the choline chloride and/or trimethylamine help prevent the components of the formation (e.g., the sand and/or clay) from swelling and/or migrating while they are in contact with the fracturing fluids. Once the addition of fracturing fluid and thereby the choline chloride and/or trimethylamine is halted, they dilute out, and the components of the formation begin to swell and/or migrate in the reservoir water thereby reducing the permeability of the formation and the rate of hydrocarbon production. Due to this time limited effect, choline chloride and trimethylamine are often referred to as temporary clay stabilizers.
The composition and behavior of shale formations are notably different than those made of sand and/or clay. Shale consists of extremely fine (micron to submicron sized) particulates that are held together with water soluble salts (e.g., calcium chloride and/or barium chloride). Typically, shale formations have very low levels of permeability (often expressed in terms of microdarcy or nanodarcy (i.e., factors of 1000 lower than clay or sand formations) due to the extremely tight packing of its component minerals.
In shale formations, fracturing water or reservoir water dissolves water soluble minerals causing the formation to lose its structural integrity and plug the fractured zone with fines. Correspondingly, temporary clay stabilizers (e.g., choline chloride and/or trimethylamine) have displayed little effect on shale stability and cores start to plug shortly after the injection of water solutions containing low and even high concentrations (or percentages) of temporary clay stabilizers.
Notably, plugging of the core mirrors events happening during and after the fracturing of the shale formation. Fracturing the shale formation includes forcing millions of gallons of water into the shale (which dissolves the water-soluble salts and the shale begins to collapse), then removing the water of which less than 10% to 15% is typically recovered. This recovered water contains high levels of fine, suspended material, indicative of the collapse of the shale structure and the production of huge amounts of fines. Hydrocarbon production (e.g., natural gas and/or oil) from these systems might be steady for a short period but then rapidly declines, indicative of the disintegration of the formation and blockage of the fractured area.
A fracturing fluid that includes a permanent clay stabilizer, that additionally stabilizes shale formations, could increase hydrocarbon production, increase the amount of recovered water, and reduce the fines content of this water.